Coal plant retirements

During 2009, 2010, and 2011, a combination of factors converged to produce a wave of coal plant retirement announcements by plant operators. These factors included:
 * The continued aging of the coal fleet, in which the median generating station was built in January 1966. (See Table 1 below) Since their efficiency is lower than newer plants, older plants are typically run less often and have poorer economics.
 * New and proposed EPA regulations, including the proposed Clean Air Transport Rule, the proposed Coal Combustion Residuals rule, the proposed Tailoring Rule (covering greenhouse gas emissions), the Ozone NAAQS (National Ambient Air Quality Standards), the forthcoming National Emission Standard for Hazardous Air Pollutants (NESHAPs), and cooling water regulations under section 316(b) of the Clean Water Act.
 * Low prices of power from natural gas plants.

Coal plant retirements were the subject of a number of several studies released in 2010:
 * Metin Celebi, "Potential Coal Plant Retirements Under Emerging Environmental Regulations" The Brattle Group, December 8, 2010
 * "Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability," M.J. Bradley & Associates LLC, August 2010
 * "Coal‐Fired Electric Generation Unit Retirement Analysis," ICF International for The INGAA Foundation & INGAA, May 18, 2010
 * "Growth from Subtraction," Credit Suisse, September 23, 2010

Projected retirements range from 25,000 - 60,000 megawawatts
According to one analysis, the new regulations are expected to push approximately 25,000 - 40,000 megawatts (MW) of smaller, older coal plants into retirement, in addition to the 5,000 MW of retirements that have already been announced. Another analysis estimated that 50,000 MW of capacity is "at risk" of retirement. A third analysis placed the total at 60,000 MW between 2013 and 2017.

Here's a breakdown of existing U.S. coal-fired generating units (not overall plants) by age:

Recent and Upcoming Retirements and Conversions
The following sortable table lists recent and upcoming (including probable) coal plant retirements and conversions in the United States. To sort the table by a column, click on the column header. Clicking a second time on the header will reverse the order of the sort.

Alabama, Kentucky, Tennessee: TVA to phase out 18 coal units, install pollution controls (April 2011)
In August 2009, CEO Tom D. Kilgore announced that TVA was studying the possibility of closing its John Sevier Fossil Plant in Tennessee and the oldest six units at its Widows Creek Fossil Plant in Alabama. A federal judge has ordered TVA to install pollution equipment on the plants by the end of 2013, at an estimated cost of more than $1 billion. However, the company has not yet budgeted any money for the improvements. In 2010 TVA is planning to begin building an $820 million gas-powered plant to replace the generation at its John Servier Plant. The agency has already reduced power production from the oldest six units at Widows Creek. Environmental groups want TVA to shut down or convert to cleaner fuels the oldest and least efficient of its coal plants, including Widows Creek, John Sevier, and Johnsonville plants.

On April 14, 2011, North Carolina settled a 5-year-old lawsuit - North Carolina v. TVA - with the TVA over emissions from its coal-fired plants. The deal was part of a larger settlement with the U.S. Environmental Protection Agency over TVA violations of the clean air act at 11 of its coal-fired plants in Alabama, Kentucky and Tennessee.

As part of the North Carolina agreement, TVA agreed to phase out 18 units of its coal plants, adding up to 2,700 MW, and to install modern pollution controls on three dozen additional units. The phase out includes two units at the John Sevier Fossil Plant, all 10 units at the Johnsonville Fossil Plant, both in Tennessee, and six units at the Widows Creek Fossil Plant in north Alabama.

As part of the EPA agreement, TVA will invest an estimated $3 to $5 billion on pollution controls, invest $350 million on clean energy projects, and pay a civil penalty of $10 million.

Colorado: Closure Planned for W.N. Clark Station
It was announced in the fall of 2010 that Black Hills Energy proposed retiring its two coal-fired units at the Clark Station in Canon City and would build a unit in Pueblo, Colorado that would be powered by natural gas. The retirement would be part of the company's proposal to reduce its greenhouse gas emissions. The proposal will be decided on by the Colorado Public Utilities Commission by the middle of December, 2010. The company originally stated it would consider using biomass to replace the coal at the plant, but later stated that it would cost too much to run the units on biomass. On December 15 2010, the Public Utilities Commission approved Black Hills Energy's plan to close its coal-fired power plant in Canon City as well as an associated rate increase for customers estimated at about 5 percent. Black Hills opted to expand its gas-fired plant presently under construction in Pueblo to replace the load generated by the Clark plant. The Pueblo plant is expected to be operational by the end of 2012, and could replace the Canon City plant immediately at that point.

Colorado: Arapahoe Station and Cameo Station
In August 2008, Colorado regulators approved Xcel Energy’s plan to shut down two coal plants: the Arapahoe Station (Denver) and the Cameo Station (east of Grand Junction). According to Western Resource Advocates, "The utility’s decision to shut down the plants has been praised as the nation’s first voluntary effort to cut coal power generation in an attempt to reduce greenhouse gas emissions. In its decision to support Xcel’s plan, the Colorado Public Utilities Commission (PUC) cited public health benefits and shared concerns about carbon emissions as major selling-points in the company’s groundbreaking proposal. The verdict marks a collective effort to move the state and its utilities toward the carbon reduction goals outlined in Governor Bill Ritter’s Climate Action Plan."

Xcel plans to replace the combined 229 MW of coal power with 850 MW of wind power and a 200 MW utility-scale solar power plant with storage capacity by 2015. Another key component of Xcel’s proposal, to build a 480 MW natural gas plant at the Arapahoe station, has been postponed pending approval by the Colorado PUC.

Colorado: Units at Cherokee and Valmont Generating Stations
The Cherokee Station 4 coal-fired plant is also scheduled to be shuttered in 2022. However, Xcel Energy announced in November 2010 its intent to close the plant, located north of Denver, in 2017, five years earlier than expected. The change of plans comes on the heels of the recently enacted Colorado Clean Air-Clean Jobs Act. As part of the legislation, Xcel receives financial incentives in exchange for a $1.3billion program of phasing out coal-fueled plants in favor of natural gas. The program targets plants in Boulder and Denver for conversion while facilities in Brush and Hayden would be upgraded to reduce pollution.

As of November 2010, Xcel is also considering shutting down its Valmont Station Unit 5.

Delaware: Indian River Power Station Units 1 and 2
Under a 2007 consent decree reached with the Delaware Department of Natural Resources and Environment, NRG Energy agreed to shut down Indian River Power Station Units 1 and 2 in 2010 and 2011. Unit 1 is an 82 MW unit built in 1957; Unit 2 is an 82 MW unit built in 1959. The company also agreed to install air pollution controls on Units 3 and 4 by the end of 2011 to reduce emissions of nitrogen oxides, sulfur dioxide and mercury.

Delaware: Indian River Power Station Unit 3
On February 3, 2010, the Delaware Department of Natural Resources and Environment announced that it is evaluating a potential agreement with NRG Energy to shut down Indian River Power Station Unit 3, a 177 MW generator built in 1970, after operating the plant through 2013. The plan would replace a previous plan to install pollution controls and continue to operate the plant for decades. According to the DNREC, no permanent jobs are expected to be lost as a result of the shutdown due to attrition, retraining, and redeployment. According to the DNREC, benefits of the shutdown include the following: Expected environmental benefits of the shutdown include:
 * Elimination of between 30 and 40 billion gallons of cooling water drawn annually from Indian River;
 * Elimination of annual kills of aquatic life including hundreds of thousands blue crabs, millions of bay anchovy, and hundreds of thousands of Atlantic menhaden, Atlantic croaker, winter flounder and weakfish;
 * Reduction by about 1,173 tons annually of nitrogen oxide and 6,252 tons of sulfur dioxide;
 * Elimination of 837,000 tons annually of the greenhouse gas carbon dioxide;
 * Reduction in annual fly ash production of between 40,000 and 70,000 tons; and
 * Reduction of mercury emissions by five pounds annually.

Florida: Crystal River to close by 2020, replaced by nuclear plant
In December 2008, Progress Energy Florida announced it will close two of the state's worst polluting coal-fired generators when its new Levy County nuclear plant is up and running in 2020. The company said the closure of two units at its Crystal River Energy Complex in Citrus County represents the equivalent of removing 830,000 vehicles from Florida's roads. The decision follows months of talks with state officials, including Gov. Charlie Crist and Department of Environmental Protection Secretary Michael W. Sole, said Progress Energy Florida chief executive Jeff Lyash. Crist has hoped to reduce state carbon dioxide emissions to the 1990 level by 2025. The scheduled closure of the two Crystal River plants means the company would be 60 percent of the way toward the governor's goal, according to Progress Energy officials. Independent studies have listed the two coal plants among the nation's top 50 polluters.

The energy created by the two Crystal River coal plants, which opened in 1966 and 1969, will be replaced by the new nuclear plant set to be built at a cost of $17-billion in Levy County. Two coal-fired power generators will remain in operation at the Citrus County site, as will a nuclear reactor. Progress Energy will spend $1.3-billion installing air emission-reduction equipment at the two remaining coal-fired plants. Early in 2007, Progress Energy won approval to raise bills 25 percent starting in January to pay for higher 2008 fuel costs and for early costs of the $17-billion nuclear project. The nuclear charge will add about $13 a month to the bill of the average residential customer, about 10 percent more.

Georgia: Georgia Power plans to retire Harlee Branch units 1 and 2 by 2013
In March 2011, Georgia Power announced that it expects to request approval from the Georgia Public Service Commission to decertify two coal-generating units 1 and 2 at the Harllee Branch Generating Plant, totaling 569 megawatts. The company plans to ask for decertification of the units as of the effective dates of the Georgia Multipollutant Rule, which are currently anticipated to be Dec. 31, 2013 for unit 1 and Oct. 1, 2013 for unit 2. GP said the costs of upgrades would be uneconomical for its customers. The commission is expected to vote on the decertification request in spring 2012.

Georgia: McDonough Steam Generating Plant
In August, 2009, the Chattanooga Times Free Press reported that Georgia Power is moving ahead with plans to replace the McDonough Steam Generating Plant in Smyrna, Ga., with a natural gas-fired plant.

Illinois: Vermillion to close in first quarter 2011
On Dec. 28, 2010, Dynegy announced that it plans to mothball its Vermilion Power Station in Illinois in the first quarter of 2011. Factors influencing the company’s decision, according to a news release from Dynegy, include the relatively small size of the facility, older technologies and coal delivery challenges that lead to high production costs, as well as weak electricity demand, low prices for power and uncertainties over future regulation. Vermilion’s coal is transported from western states by rail to Danville and then trucked to the Vermilion site. This is the most significant factor leading to Vermilion’s higher production costs, according to the news release.

Illinois: University of Illinois Abbott Power Plant
In May 2010, the University of Illinois pledged to stop using coal within seven years as part of a plan to reduce energy use and cut carbon emissions: the Illinois Climate Action Plan, finalized that month. The plan was developed by the campus Sustainability Council. It was submitted to the American College and University Presidents' Climate Commitment, signed by more than 600 schools. The UI is the first Big Ten school to formally submit a climate plan.

To meet its goals, UI is considering alternative fuels that could be used by University of Illinois Abbott Power Plant or another central generation facility, officials said. University buildings – which account for 85 percent of the campus's energy use – are primarily heated by steam produced at Abbott. The plant also produces electricity as a byproduct, with the UI buying additional electricity from private suppliers. Abbott runs primarily on natural gas and coal, with the fuel mix decided by market costs, according to UI officials. The sustainability team concluded that Abbott's natural gas capacity can provide almost enough steam to meet campus demand by itself and should be able to do so in a few years if conservation trends continue. The campus burned 94,171 tons of coal in fiscal 2009, although that figure has dropped 30 percent in fiscal 2010 so far, said Tom Abram, sustainability coordinator in UI Facilities and Services.

Illinois: Will County and Waukegan to close
As part of a 2006 agreement with the state of Illinois, Midwest Generation said it plans to shut down the three smallest generating units in its fleet -- two units at the Will County Generating Station in Romeoville and one at its Waukegan Generating Station -- between the end of 2007 and the end of 2010. The company also has committed that its smallest plant -- the single-unit Fisk Generating Station in Chicago -- will either have additional controls for sulfur dioxide emissions or be shut down by the end of 2015. The same agreement to shut down or install additional controls applies to the Waukegan Generating Station by the end of 2014 and to the Crawford Generating Station in Chicago by the end of 2018.

In November 2010, the Illinois EPA issued a construction permit to Midwest Generation to install flue gas desulfurization equipment to cut emissions of sulfur dioxide and particulates from Waukegan Generating Station Unit 7. The permit authorizes the company to use a dry scrubbing system with sodium-based sorbents to cut sulfur dioxide emissions as required by state and federal rules at the company's Waukegan coal-fired power plant unit 7 north of Chicago. Midwest Generation spokesman Doug McFarland said the company may wait until "sometime in 2012" to decide whether to invest in the pollution-control equipment or shut down Unit 7. The decision will depend on market conditions and air quality rules.

Indiana: Tanners Creek Plant, Units 1, 2 and 3
On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation.

Included in the plan:
 * Tanners Creek Plant, Lawrenceburg, Indiana - Units 1, 2 and 3 (495 MW) retired by Dec. 31, 2014; Unit 4 (500 MW) would continue to operate with retrofits.

Indiana: Dean Mitchell station to close, pollution controls at three other plants
On January 13, 2011, the Obama administration brokered a settlement in which Northern Indiana Public Service Co. will permanently shut down an idled coal-fired power plant in Gary, Indana - the Dean Mitchell Generating Station - and spend $600 million to install and improve pollution controls at the company's three other aging electric generators - Schahfer Generating Station in Wheatfield, Bailly Generating Station in Chesterfield, and the Michigan City Generating Station. NIPSCO faced legal troubles for upgrading the power plants to keep them operating while failing to install modern pollution controls required under the Clean Air Act's New Source Review provisions. The plants avoided the toughest provisions of the law for decades, in part because regulators assumed during the 1970s that they wouldn’t be running much longer.

Indiana: Duke ordered to shut down three coal-fired units
On May 29, 2009, U.S. District Judge Larry J. McKinney ordered Duke to shut down three units of the Wabash River Generating Station in Indiana for violations of the federal Clean Air Act. In 2008, a jury found that Duke-owned Cinergy had modified the facilities without installing best-available pollution control technology. In his ruling, Judge McKinney cited increased sulfur dioxide emissions from the units and gave a deadline of September 30, 2009 for closing them. Duke's Chief Legal Officer Marc Manly said the company was disappointed with the court's decision to "accelerate the shutdown." The units, which supply 39 percent of the station's power, were slated to be taken off line in 2012.

Indiana: Duke proposes closing two units at Gallagher station
Under a plan submitted to the Indiana Utility Regulatory Commission on May 24, 2011, Duke Energy said it plans to shut down two coal-burning units at its Gallagher Generating Station and purchase a share of the Cayuga Generating Station in Indiana to make up the difference. The plan is being considered as a potential settlement option in a more than a decade-old lawsuit the company has with the EPA. Duke had been exploring the idea of converting two of the Gallagher burners to natural gas via running a gas pipeline from Kentucky. But the gas pipeline would cost $71 million, while Duke would pay $68 million for its share of the Vermillion Plant, owned by both Duke Ohio — an unregulated subsidiary of Duke Energy — and Wabash Valley Power Association. Duke Energy would own 62.5 percent of that plant and Wabash would own the remainder.

The lawsuit that initiated the filing relates to air quality: the EPA alleges Cinergy — which merged with Duke Energy in 2006 — undertook six power-plant upgrades that added new coal burners in Indiana and Ohio without obtaining new permits as required by New Source Review provisions. Both the Indiana Utility Regulatory Commission and the Federal Energy Regulatory Commission will have to approve either option before Duke moves ahead.

Indiana: Dominion to shut down State Line Plant between 2012 and 2014
In a May 2011 conference call with financial analysts, Dominion executives announced they had decided that, financially, it is not worth upgrading the State Line Plant to comply with the federal Clean Air Act. The company plans to shutter State Line as early as 2012 and no later than 2014.

Iowa: Alliant to close coal boilers at six sites
According to plans filed with the Minnesota Public Service Commission on November 1, 2010, Alliant Energy plans to close coal-fired boilers at six sites in Iowa:


 * Sixth Street Generating Station (all units) (Cedar Rapids)
 * Prairie Creek Generating Station Unit 2 (Cedar Rapids)
 * Dubuque Generating Station Unit 2
 * Lansing Power Station Units 2 and 3
 * Milton Kapp Generating Station Unit 1 (Clinton)
 * Sutherland Generating Station Unit 2 (Marshalltown)

The plan also designates two boilers at Dubuque Generating Station and another at the Sutherland Generating Station for retirement in 2015. Of this list, only one boiler (Lansing 3) is currently operational, and the replacement generation will come in significant part from running newer coal boilers at higher capacity.

Kentucky: Big Sandy Plant Units 1 and 2
On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation.

Included in the plan:


 * Big Sandy Plant, Louisa, Ky. - Units 1 and 2 (1,078 MW) retired by Dec. 31, 2014; Big Sandy Unit 1 would be rebuilt as a 640-MW natural gas plant by Dec. 31, 2015.

Kentucky: Henderson Station One
Henderson Station One was a coal-fired power station owned and operated by the Henderson City Utility Commission in Henderson, Kentucky. Citing rising costs and mounting environmental regulations, Henderson Municipal Power and Light closed the 58-year-old Station One power plant on Water Street at the end of 2008. HMP&L said it told the 13 full-time employees at the plant that it would assist them in identifying new job openings at HMP&L, the city of Henderson or the Henderson Station Two power plant. According to HMP&L General Manager Gary Quick, "There are constantly openings at Station Two and other plants out there."

Kentucky: LG&E Energy and Kentucky Utilities Company discuss retiring three plants
According to long-range planning documents filed in mid-April 2011 with the Public Service Commission, LG&E Energy and Kentucky Utilities Company are making initial plans to retire coal-burning units at three aging power plants by 2016, including the Cane Run Station in western Louisville, KU's Green River Generating Station in Central City in Western Kentucky, and KU's Tyrone Generating Station in Versailles, which has already been mothballed temporarily. A PPL spokeswoman for the two companies, Chris Whelan, said: “This is not a final decision," calling the planning document “a snapshot in time” to keep state regulators up to speed on the company's long-range thinking. In the utilities' latest joint Integrated Resource Plan, updated every three years and made public by the PSC on April 22, 2011, the companies' experts call for adding three times as much electricity-generating capacity from natural gas as the utilities retire from coal. They say the new power mix is what will be needed to keep their rates as low as possible amid tightening environmental regulations, even as electricity demand grows. In all, 979 megawatts of coal-burning capacity would be retired in 2016, while the two utilities would add 2,721 megawatts from natural gas — though it's not clear yet where the new gas turbines would be. The utilities currently produce about 8,000 megawatts of electricity.

Massachusetts: Dominion's Salem and State Line Plants
On November 18, 2010, Dominion said it expects to shut the Salem Harbor coal/oil-fired power plant in Massachusetts within seven years "as the high cost of keeping up with ever more stringent pollution rules could make it uneconomic to keep operating the plant," a company executive said. Dominion CFO Mark McGettrick also told investors that, in addition to the 738-megawatt Salem Harbor, the company may also close the 515 MW State Line Plant in Indiana. The first of the coal units still operating at both plants entered service more than half a century ago. The environmental regulations McGettrick referred to was the U.S. Environmental Protection Agency's planned one-hour ozone rule for 2015-2017, known as the Transport Rule: "If that rule goes into effect, we do not plan to install expensive environmental controls at either of those two stations," Dominion spokesman Dan Genest told Reuters. Independent System Operator (ISO) New England, which operates the regional power grid, could again decide Salem Harbor is needed for "reliability" -- as the ISO has over the past couple of years. Dominion recently asked the ISO to withdraw the plant from the grid's June 2011 forward capacity auction for 2014-15. The ISO is not expected to decide on the request until 2011. Dominion reportedly wants to withdraw from the auction not because the company wants to shut the plant but because the capacity price has been coming down over the past few years. The capacity auction pays power suppliers (and demand response customers who agree to reduce usage) to remain available to maintain the long-term reliability of the grid.

In Feb. 2011, Dominion said it could retire the Salem plant in June 2014 when the 2013-2014 forward capacity contract ends, if it cannot recover the cost of environmental upgrades needed to run after that date. In October 2010, Dominion filed what is known as a "permanent delist bid" that included a request to recover the cost of the environmental upgrades that would have allowed the plant to opt out of the 2014-2015 forward capacity auction. The ISO rejected that bid in January 2011.

In May, 2011, Dominion announced that all four units of the plant, including the three units that use coal, would shut down by June 2014.

Massachusetts: NRG Energy to shut Somerset Power Generating Station
In November, 2009, NRG Energy announced that it would close the Somerset Power Generating Station, a 174 MW coal plant in Somerset, Massachusetts, on January 2, 2010. A company spokesman cited "market forces" and a "requirement that we close down or repower [by] September of 2010." NRG plans to convert the plant from burning coal to a plasma gasification process, which breaks down coal into its component parts before converting it into energy. No timetable for that conversion has been announced.

Opponents of the Somerset plant, including the Conservation Law Foundation, the Massachusetts Clean Air Coalition, and the Toxics Action Center, expressed optimism that the conversion to gasification would prove to be infeasible. "Shutting down Somerset for an indefinite period shows that this old coal-fired plant is not necessary for reliability and undermines the likelihood that the coal gasification project will move forward," said Shanna Cleveland, staff attorney for CLF.

Sylvia Broude, lead organizer for Toxics Action Center, said, “Closing this plant will immediately improve public health in the area, and we will continue to fight to ensure that NRG will not proceed with experimental coal gasification technology that is expected to have significant public health impacts.”

In December 2009, the Conservation Law Foundation (CLF) released a statement saying that an announcement by the Deval Patrick administration would likely stall NRG's plans to retrofit the smaller of the Somerset plants to burn biomass. According to CLF, the state of Massachusetts intends to maintain its incinerator moratorium, suspending projects that would burn construction and demolition debris pending a complete environmental review.

Michigan: S.D. Warren Muskegon Power Plant
S.D. Warren Muskegon Power Plant was a 51-megawatt (MW) coal-fired power station owned and operated by Sappi, a South African multinational pulp & paper corporation, in Muskegon, Michigan. The plant provided power to Sappi's Muskegon pulp & paper mill until the entire facility was shut down in 2009.

Minnesota: Xcel Energy plans to retire Black Dog Generating Station and replace with natural gas
On March 15, 2011, Xcel Energy asked Minnesota regulators to approve a certificate of need for a project of retiring Black Dog Generating Station units 3 and 4, and replace the units with natural gas generators. If approved, the new gas plants would begin site preparation in 2012 and come on line in 2016. (Black Dog 1 and 2 were coverted to natural gas in 2002.)

Missouri: Ameren's Meramec plant may close between 2015 and 2020
In Feb. 2011, Ameren filed its integrated resource plan, outlining the company's strategy for meeting energy demand for the next 20 years, and said the updated coal regulations for air pollution, water use and coal waste disposal would probably prompt the company to close its 58-year-old Meramec Power Plant in St. Louis, Missouri, sometime between 2015 and 2020. The company is looking at a nuclear- or natural gas plant to make up for the plant, rather than improvements in energy efficiency. Although the company found in the report that efficiency is cheaper, they said the company cannot collect the revenue from efficiency measures quickly enough to please its shareholders.

Nevada: Mohave Generating Station
In 2005, the Mohave Generating Station ceased operations due to a Clean Air Act lawsuit and because Navajo and Hopi tribes passed resolutions ending Peabody’s use of the Black Mesa aquifer. According to the EPA, the coal plant was the dirtiest in the Western U.S., emitting up to 40,000 tons of sulfur dioxide per year.

New Jersey: Howard Down Generating Station
According Bill O’Sullivan, administrator of air quality for the New Jersey Department of Environmental Protection, the Howard Down Generating Station, a 25 MW coal plant operated by Vineland Municipal Electric in New Jersey, was scheduled to replace its last coal-fired generator with natural gas in 2010.

New Mexico: APS to close Four Corners Steam Plant Units 1, 2, and 3
On November 8, 2010, Arizona Public Service announced that it had entered into an agreement to purchase Southern California Edison's share of Four Corners Steam Plant Units 4 and 5, which it plans to retrofit with additional emission controls. The company will close Units 1, 2, and 3. There will be no layoffs at the plant, which employs 549 workers, 74 percent of whom are Navajo. Closing the three units will reduce the capacity of Four Corners by 633 megawatts (nameplate capacity) or 560 megawatts (net summer capacity). Units 1 and 2 were built in 1963, and Unit 3 was built in 1964.

New Mexico and Utah: Los Angeles Department of Water and Power 2010 IRP calls for accelerated pullout from Navajo Generating Station and Intermountain Power Station
The 2010 Integrated Resource Plan, a strategic plan for the next 20 years, recommended that LADWP add 630 new megawatts of solar capacity by 2020 and 970 megawatts of solar capacity by 2030. The plan recommended 580 megawatts of new wind power by 2020. The plan designated that 40 percent of solar be in-basin. It recommended incentive programs, feed-in tariff schemes, and other mechanisms for promoting solar. The plan recommended ending purchases of power from the coal-fired Navajo Generating Station by 2014, which is five years ahead of the deadline established by California state law. The plan recommends ending use of power from the coal-fired Intermountain Power Station by 2020, seven years ahead of the scheduled end of such purchases. The plan states that "LADWP is open to a mutually agreeable early compliance plan between the project participants that preserves the site and transmission for clean fossil and renewable generation."

====Table 1: Generation Sources for LADWP in 2010 and 2030 ====

New York: AES Westover closes in March, 2011
In March 2011 the AES Westover retired its Unit 8 power station in March 2011. Additionally, AES announced it wanted to sell four of its New York coal plants, including Westover.

North Carolina: Progress Energy announces plan to close N.C. coal plants
On August 18, 2009, Progress Energy announced a plan to close 3 units at its Lee Steam Plant in North Carolina. The company is seeking regulatory approval to build a new natural gas-fired plant at the site. As proposed, the new plant would increase generation capacity at the site by about 550 megawatts, while still reducing overall emissions, including carbon dioxide. The project will cost an estimated $900 million, and is expected to be operational in 2013.

On December 1, 2009, Progress Energy Carolinas announced that by the end of 2017 it would permanently close all of its North Carolina coal plants without sulfur dioxide scrubbers. The 11 units at L.V. Sutton, Cape Fear, Weatherspoon, and Lee total almost 1,500 megawatts and represent about a third of the utility's coal-fired power generation in N.C. The retirement plan includes the following:


 * Lee is still scheduled for retirement in 2013.
 * Sutton is slated for closure in 2014. Progress hopes to replace it with a natural gas-fired power plant.
 * Cape Fear and Weatherspoon will be shut down between 2013 and 2017. The company is considering converting 50 to 150MW of the total capacity to burn wood waste.

The closure plan was filed in response to a request by the N.C. Utilities Commission, which ordered Progress to provide its retirement schedule for "unscrubbed" coal-fired units in North Carolina. The request was a condition of the commission's approval of Progress' plan to close Lee and build a 950-MW natural gas plant at the site.

North Carolina: Progress Energy announces plan to close Lee coal plant
On August 18, 2009, Progress Energy announced a plan to close 3 units at its Lee Steam Plant in North Carolina. The company is seeking regulatory approval to build a new natural gas-fired plant at the site. As proposed, the new plant would increase generation capacity at the site by about 550 megawatts, while still reducing overall emissions, including carbon dioxide. The project will cost an estimated $900 million, and is expected to be operational in 2013. North Carolina State regulators approved the plan on October 1.

North Carolina: Duke to close units at Cliffside, Buck Steam, Lee Steam, and Riverbend
Duke has agreed to retire 800 megawatts of older coal units as part of an N.C. permit to build a new 825-megawatt unit under construction at the Cliffside Plant in Rutherford County. That will shutter four old units at Cliffside, two at Buck Steam Station in Rowan County, three at Dan River Steam Station, and two at Riverbend Steam Station in Gaston County.

In September 2010, Duke Energy said it might close seven coal-fired units at its Carolinas power plants within five years as environmental regulations intensify. It may retire by 2015 all coal-fired units for which it's not economical to install sulfur dioxide controls called scrubbers. That would increase by 890 megawatts the coal plants Duke had planned to retire in 2009. The retired units would be at Duke's Riverbend Steam Station in Gaston County, Buck Steam Station in Rowan County, and Lee Steam Plant in Anderson County, S.C. Duke said it might convert Lee from coal to natural gas fuel.

Ohio: Richard H. Gorsuch Generating Station
On May 18, 2010, the U.S. Environmental Protection Agency (EPA) and the U.S. Justice Department announced that American Municipal Power - Ohio would be permanently retiring the Richard H. Gorsuch Generating Station by Dec. 31, 2012, under a settlement to resolve violations of the Clean Air Act's New Source Review requirements. Interim sulfur dioxide and nitrogen oxide emission limits will be implemented until that date. Also part of the settlement, AMP will spend $15 million on an environmental mitigation project and pay a civil penalty of $850,000.

Ohio: Picway Power Plant, Conesville Power Plant, and Muskingum River Plant
On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. The cost of AEP’s compliance plan could range from $6 billion to $8 billion in capital investment through the end of the decade.

AEP’s current plan for compliance with the rules as proposed includes permanently retiring the following coal-fueled power plants:
 * Picway Power Plant, Lockbourne, Ohio – 100 MW (retired by Dec. 31, 2014).

In addition, six other plants would reduce their power output, including:
 * Conesville Power Plant, Conesville, Ohio - Unit 3 (165 MW) retired by Dec. 31, 2012; Units 5 and 6 (800 MW total) would continue operating with retrofits; and
 * Muskingum River Plant, Beverly, Ohio - Units 1-4 (840 MW) retired by Dec. 31, 2014; Muskingum River Unit 5 (600 MW) may be refueled with natural gas with a capacity of 510 MW by Dec. 31, 2014, depending on regulatory treatment in Ohio.

Ohio: FirstEnergy's Lake Shore Plant, Eastlake Power Plant, Ashtabula Plant, and Bay Shore Plant
On August 12, 2010, FirstEnergy announced it will throttle back power production at four of its smaller, coal-burning power plants, beginning in September and continuing for three-years. The company cited the lackluster economy, low demand for power, and pending federal rules tightening emission standards. The plants are the Lake Shore Plant in Cleveland, OH, all but the largest boiler at the Eastlake Power Plant in Lake County, OH, the Ashtabula Plant, and three of four boilers at the Bay Shore Plant near Toledo, OH. The largest Bay Shore unit, which burns petroleum coke from the nearby BP/Husky oil refinery, will continue operating. The four power plants have not been running flat out for some time; instead, the company has kept them in reserve, ramping up production as needed. Altogether the power plants have a total generating capacity of 1,620 megawatts, they accounted for less than 7 percent of total production in 2009. One megawatt is 1 million watts and enough electricity to power about 800 homes. FirstEnergy said the slowdown will reduce operating costs but could force the company to write off $287 million in the value of its assets, reducing third quarter earnings by 59 cents per share.

Ohio: FirstEnergy to close Burger Plant units 4 and 5
According to a Nov. 17, 2010 report from Power-Gen Worldwide, FirstEnergy Corp. is planning to permanently shut down two coal-fired units, Units 4 and 5, at the Burger Plant by the end of the year. The units were included in the 2005 Consent Decree settlement with the U.S. Environmental Protection Agency, and FirstEnergy had the option to re-power, install scrubbers, or shut down the units as part of an effort to reduce the company's sulfur dioxide emissions. Rather than refit the Burger plant units, First Energy will complete a $1.8 billion retrofit at its Sammis Plant in Stratton, Ohio, according to the report.

Ohio: Ohio University Lausche Heating Plant
In March 2011, the Ohio University administration made a promise not to consider coal as an energy source for a new heating plant. The administration has said that it must replace the Lausche facility by the year 2016, as the useful life of its boilers draws to a close.

Ontario shutting 4 plants, considering conversion for remaining 11 plants
Ontario Power Generation will shut down four of its 15 coal-fired power plants in late 2010. The closures include two of eight units at Nanticoke Generating Station, and two of four units at Lambton. The four plants represent about 2,000 megawatts of total generation capacity. The closure of the four units, in addition to the 2005 closure of Lakeview Generating Station in 2005, will reduce the Canadian province's coal capacity by 40 percent. OPG said it would continue to assess converting its remaining 11 units to other types of fuel such as biomass, beginning with the conversion of Atikokan Generating Station by 2012.

Oregon: Boardman Plant
On January 14, 2010 it was announced that Portland General Electric will be closing its 601 MW Boardman Plant twenty years ahead of schedule. The plant will close in 2020 instead of 2040. The plant was originally going to invest more than a half billion dollars in pollution controls (scrubbers) by 2017 to comply with EPA and state clean air regulations, then keep it running until 2040.

Instead, the company wants regulators to allow it to make a $45 million investment by 2011 to partially clean up its emissions of mercury and oxides of nitrogen, then operate the plant until 2020. The Oregon Sierra Club and Friends of the Columbia Gorge argue, that while a 2020 close date is better than a 2040 closure, it is still more economical for the plant to shut its doors in 2014.

On February 1, 2010 it was announced that PGE was considering using biomass to continue operating the plant after it ends its use of coal in the future. PGE is said to be considering if it can replace all of the millions of tons of coal it burns every year at Boardman with plant based material that has been pre-treated through a process called torrefaction. While still in experimental phases, torrefaction produces a substance similar to coal, and is also energy intensive to produce. Critics on the other hand cite that no commercial size torrefaction facilities exist and it is still not clear how much carbon will be used in the process of torrefaction.

Pennsylvania: Exelon announces plan to shut coal plants
On December 2, 2009, Exelon announced that it would retire Cromby Generating Station and two units at Eddystone Generating Station in 2011. The closures include 144 MW of coal-fired power at Cromby and another 588 MW at Eddystone. Eddystone will continue to operate 820 MW of natural gas- and oil-fired generation. Exelon senior vice president Doyle Beneby said the retirements were due to "decreased power demand, over supply of natural gas and increasing operating costs," adding that, "these aging units are no longer efficient enough to compete with newer resources." The announcement comes just one day after Progress Energy said it would shut 11 aging coal-fired power units totaling almost 1,500 MW in North Carolina.

Tennessee: TVA Announces Plans to Retire John Sevier Fossil Plant Units 1 and 2
On August 24, 2010 TVA announced that it will retire 9 coal-fired generating units totalling about 1,000 megawatts of capacity at three locations beginning in fiscal year 2011: Shawnee Fossil Plant Unit 10 in Kentucky, John Sevier Fossil Plant Units 1 and 2 in Tennessee, and Widows Creek Fossil Plant Units 1-6 in Alabama. In addition TVA stated that it will eliminate 200 jobs at these plants starting in 2011, but the workers will be placed in other positions within TVA. CEO Tom D. Kilgore said that TVA would replace the sidelined coal power with greater reliance on nuclear power and energy efficiency.

Texas: San Antonio coal plant to be 1st in Texas to close
In June 2011 CPS Energy announced that its San Antonio based J.T. Deely Station would be shut down in 2018. The coal-fired power plant that supplied electricity in San Antonio since the 1970s. The CPS Deely plant is the first publically-owned coal plant announced to retire in Texas.

According to the president of CPS Energy, Doyle Beneby, their plans will cut emissions of sulfur dioxides by 85%, nitrus oxide by 30%, carbon dioxides by 25%, and mercury by 58% by the time the plant closes.

"Closing Deely coal plant and transitioning to a clean energy economy will be a tremendous benefit for San Antonio," according to a joint news release released by the Sierra Club, SEED Coalition, and Public Citizen.

Texas: Welsh Power Plant, Unit 2
On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. The cost of AEP’s compliance plan could range from $6 billion to $8 billion in capital investment through the end of the decade. AEP’s current plan for compliance with the rules as proposed includes permanently retiring five of its coal-fueled power plants.

Included in the plan:
 * Welsh Power Plant, Pittsburg, Texas - Unit 2 (528 MW) retired by Dec. 31, 2014; Units 1 and 3 (1,056 MW) would continue to operate with retrofits.

Utah: Utah Smelter Power Plant
In December, 2010, Kennecott Utah Copper announced that it would repower units 1-3 of its Utah Smelter power plant to run on natural gas. However, unit 4 of the plant will continue to be powered by coal.

Virginia: Glen Lyn Plant and Clinch River Plant
On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. The cost of AEP’s compliance plan could range from $6 billion to $8 billion in capital investment through the end of the decade.

AEP’s current plan for compliance with the rules as proposed includes permanently retiring the following coal-fueled power plants:
 * Glen Lyn Plant, Glen Lyn, Va. – 335 MW (retired by Dec. 31, 2014).

In addition, six other plants which will reduce their power output, including:
 * Clinch River Plant, Cleveland, Va. - Unit 3 (235 MW) retired by Dec. 31, 2014; Units 1 and 2 (470 MW total) would be refueled with natural gas with a capacity of 422 MW by Dec. 31, 2014.

Virginia: Dominion to convert Altavista, Hopewell, and Southampton plants to biomass
In Feb. 2011, Dominion Virginia Power said it could reopen its 63 MW Altavista Power Station as a biomass electricity plant by 2013, and is starting the approval process. In Fall 2010, Dominion placed the Altavista station on “cold reserve status,” meaning it could be restarted if needed. At the time, Dominion was studying whether to convert the plant to a biomass facility. The study suggested that a biomass facility would be competitive economically against natural gas plants. If the town of Altavista grants Dominion’s special use permit request, the company said it will seek a new air permit and approval from the State Corporation Commission.

In April 2011, Dominion Resources announced that its subsidiary Dominion Virginia Power, has decided use biomass instead of coal in three of its power stations: Altavista Power Station, Hopewell Power Station and Southampton Power Station. The plants will mainly use waste wood left from timbering operations as a source of fuel. If approved by the local authority and the regulators will begin production from the converted units in 2013. The units can presently produce 63 megawatts (MW) power each and are only used when demand is at its peak. After conversion, these units will produce 50 MW each.

Virginia: Dominion proposes closing North Branch Station for approval of new natural gas plant
In a December 2010 accord reached with the National Park Service and the Virginia Department of Environmental Quality, Dominion volunteered to close its North Branch Station when the proposed natural gas-fired Warren County Power Station near Front Royal begins commercial operations, which is scheduled for late 2014 or early 2015. Emissions reductions credits from closing the station will be combined with various other offsets to be applied as the emission mitigation plan for the new power station. The agreement is conditioned upon the Virginia Air Pollution Control Board's approval of the air permit for the proposed station, other regulatory approvals and the construction and operation of the proposed station. The air board is expected to vote on Dominion's application for the Warren County air permit at its Dec. 17, 2010 meeting. The company anticipates seeking permission from the Virginia State Corporation Commission in 2011 to build the new power station.

North Branch was put in cold reserve status in August 2010, and has not been generating electricity. Without this agreement, the station could be returned to service in a short time if needed.

Washington: TransAlta to close Centralia Power Plant
On April 11, 2011 the Washington State House of Representatives voted overwhelming to approved Senate Bill 5769, which would shut down one of two boilers at the Centralia Power Plant coal-fired plant by 2020 and phase out coal-burning by 2025. TransAlta, state officials and environmental groups negotiated a deal in March 2011 to close the plant in Centralia. The measure requires the company to provide $55 million for economic development and other assistance, and to install additional air pollution controls called scrubbers to further reduce emissions of nitrogen oxides at the plant.

In exchange, TransAlta would be allowed enter into long-term agreements to sell its electricity to other utilities, which is currently prohibited by state law.

Lawmakers in the House made mostly technical changes to the bill, which passed by an 87-9 vote. The bill was later passed by the Washington State Senate.

On May 3, 2011, Governor Chris Gregoire signed legislation today that will close the plant by 2025. It was also reported that natural gas was being discussed as the replacement fuel for the TransAlta plant.

Text of SB 5769 here

West Virginia: Kammer Plant, Kanawha River Plant, and Philip Sporn Power Plant
On June 9, 2011, AEP announced that, based on impending EPA regulations as proposed, AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. The cost of AEP’s compliance plan could range from $6 billion to $8 billion in capital investment through the end of the decade.

AEP’s current plan for compliance with the rules as proposed includes permanently retiring the following coal-fueled power plants:
 * Kammer Plant, Moundsville, W.Va. – 630 MW (retired by Dec. 31, 2014) (pictured above)
 * Kanawha River Plant, Glasgow, W.Va. – 400 MW (retired by Dec. 31, 2014); and
 * Philip Sporn Power Plant, New Haven, W.Va. – 1,050 MW (450 MW expected to retire in 2011, 600 MW retired by Dec. 31, 2014).

West Virginia: Dominion's North Branch Station
In a December 2010 accord reached with the National Park Service and the Virginia Department of Environmental Quality, Dominion volunteered to close its North Branch Station when the proposed natural gas-fired Warren County Power Station near Front Royal begins commercial operations, which is scheduled for late 2014 or early 2015. Emissions reductions credits from closing the station will be combined with various other offsets to be applied as the emission mitigation plan for the new power station. The agreement is conditioned upon the Virginia Air Pollution Control Board's approval of the air permit for the proposed station, other regulatory approvals and the construction and operation of the proposed station. The air board is expected to vote on Dominion's application for the Warren County air permit at its Dec. 17, 2010 meeting. The company anticipates seeking permission from the Virginia State Corporation Commission in 2011 to build the new power station.

North Branch was put in cold reserve status in August 2010, and has not been generating electricity. Without this agreement, the station could be returned to service in a short time if needed.

Wisconsin Considers Five Plant Closures
In 2007 the Sierra Club challenged the State of Wisconsin over pollution emissions from five of its state-run coal plants used to provide heat and power to four state-run university buildings and one hospital. The plants include those that function at UW-Eau Claire, UW-La Crosse, UW-Oshkosh, UW-River Falls and Mendota Mental Health Institute. The State's Department of Natural Resources sided with the Sierra Club, and now the state of Wisconsin has to decide on whether or not to install pollution-control equipment to greatly reduce emissions, or reduce the use of coal all together. As decision is to be made by spring 2010.

The Sierra Club alleged that the millions of dollars in upgrades made at these facilities were significant and actually increased the potential for the plants to emit more pollution.

Wisconsin: Menasha Power Plant Closed
In 2009 the Menasha Power Plant in Menasha, Wiconsin stopped burning coal. In May 2011, it was reported that the plant was considering reopening with biomass pellets replacing coal as its energy source.

Sierra Club calls for closure of three coal plants in Texas
On March 18, 2011 the Sierra Club released a report stating that three of plants owned by Energy Future Holdings/Luminant in East Texas should be shut down because the facilities do not meet Clean Air Act standards and need $3.6 billion in upgrades in order to comply with federal regulations.

The three plants targeted were Big Brown, Monticello Steam Station and the Martin Lake Steam Station plant. The Sierra Club expressed concern about "the major threats to air and water pollution that citizens in the Barnett Shale [in North Texas] are dealing with firsthand."

The study recommended:
 * "[R]eplacement of three coal fired power plants built in the 1970’s (Big Brown, Monticello and Martin Lake) is a financial and environmental necessity. The plants, currently owned by Energy Future Holding/Luminant and serving North Texas are financially mismanaged, cannot compete profitably in the current market, require pollution control upgrades that are unaffordable and have suffered deep losses in market value. The financial outlook for the company and the plants going forward show very little upside. A broad look at the national and Texas energy market suggest planning tools and resources exist to ensure a smooth transition to a more financially stable and reliable supply of electricity."

Related SourceWatch articles

 * Campus coal plants
 * Coal
 * Coal and jobs in the United States
 * Coal and transmission
 * Coal-fired power plant capacity and generation
 * Coal moratorium
 * Coal plant conversion projects
 * Coal plants near residential areas
 * Comparative electrical generation costs
 * Existing U.S. Coal Plants
 * Former coal plants
 * Google Renewable Energy Cheaper Than Coal initiative
 * Gore zero-carbon proposal
 * Opposition to existing coal plants
 * Retrofit vs. Phase-Out of Coal-Fired Power Plants
 * Natural gas transmission leakage rates

External resources

 * "Beyond Business as Usual: Investigating a Future without Coal and Nuclear Power in the U.S.," Synapse Energy Economics, May 5, 2010.
 * "Coal phase out," Wikipedia
 * "Let buildings heat and cool themselves: How to kill coal in 10 years," Jon Ryann, Gristmill, February 20, 2008
 * Jon Ryann's heat pump scenario spreadsheet
 * "Power from rooftops could replace coal," Gar Lipow, Gristmill, 6/30/08
 * "Meet the Boomers: What's the best way to phase out the huge fleet of aging coal plants?" Ted Nace, Gristmill, November 11, 2008
 * "A Solar Grand Plan," Ken Zweibel, James Mason and Vasilis Fthenakis, Scientific American, December 2007.
 * "Tackling Climate Change in the U.S.: Potential Carbon Emissions Reductions from Energy Efficiency and Renewable Energy by 2030," American Solar Energy Society, January 2007.
 * "The War on Coal: Think Outside the (Coal) Pits," Khosla Ventures, 2007 (PDF file)
 * The Boardman Coal Plant: Don’t “Clean it Up” - Shut it Down!, It's Getting Hot in Here, August 20, 2008
 * Josh Galperin, "Southeast Coal Retirements Mount in 2010," CleanEnergy.org, November 22, 2010
 * "FACTBOX - U.S.coal units to retire as EPA tightens rules," Reuters, March 7, 2011